U.S. patent application number 13/621623 was filed with the patent office on 2014-03-20 for intra-bed source vertical seismic profiling.
The applicant listed for this patent is David Fraga Freitas. Invention is credited to David Fraga Freitas.
Application Number | 20140078864 13/621623 |
Document ID | / |
Family ID | 50274343 |
Filed Date | 2014-03-20 |
United States Patent
Application |
20140078864 |
Kind Code |
A1 |
Freitas; David Fraga |
March 20, 2014 |
INTRA-BED SOURCE VERTICAL SEISMIC PROFILING
Abstract
A system and method obtain a Vertical Seismic Profile (VSP). The
system includes a seismic source disposed in a first borehole at a
first depth greater than an identified depth of a interface, the
seismic source configured to emit seismic waves. The system also
includes one or more receptors disposed in a second borehole that
includes a target region of interest, the one or more receptors
configured to receive direct and reflected components of the
seismic waves.
Inventors: |
Freitas; David Fraga; (Rio
de Janeiro, BR) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Freitas; David Fraga |
Rio de Janeiro |
|
BR |
|
|
Family ID: |
50274343 |
Appl. No.: |
13/621623 |
Filed: |
September 17, 2012 |
Current U.S.
Class: |
367/57 |
Current CPC
Class: |
G01V 1/42 20130101; G01V
2210/1299 20130101; G01V 2210/161 20130101; G01V 2210/1429
20130101 |
Class at
Publication: |
367/57 |
International
Class: |
G01V 1/28 20060101
G01V001/28; G01V 1/42 20060101 G01V001/42 |
Claims
1. A system to obtain a Vertical Seismic Profile (VSP), the system
comprising: a seismic source disposed in a first borehole at a
first depth greater than an identified depth of a interface, the
seismic source configured to emit seismic waves; and one or more
receptors disposed in a second borehole that includes a target
region of interest, the one or more receptors configured to receive
direct and reflected components of the seismic waves.
2. The system according to claim 1, wherein the seismic source is
one of an explosive, an air gun, or a sparkler.
3. The system according to claim 1, wherein the identified depth is
identified based on previously obtained surface seismic data.
4. The system according to claim 3, wherein the identified depth is
based on a difference in amplitude values of reflections in the
seismic data in a given seismic section.
5. The system according to claim 3, wherein the identified depth is
based on a difference in seismic attribute values of reflections in
the seismic data in a given seismic section.
6. The system according to claim 1, wherein at least two receptors
are disposed in the second borehole, each of the at least two
receptors being equidistantly spaced from adjacent ones of the at
least two receptors.
7. The system according to claim 1, wherein the first depth of the
seismic source in the first borehole is less than a depth of the
one or more receptors and a depth of the target region in the
second borehole.
8. A method of obtaining a Vertical Seismic Profile (VSP), the
method comprising: disposing a seismic source in a first borehole
at a first depth greater than an identified depth of a reflective
interface, the seismic source being configured to emit seismic
waves; and disposing one or more receptors in a second borehole
that includes a target region of interest, the one or more
receptors configured to receive direct and reflected components of
the seismic waves.
9. The method according to claim 8, further comprising identifying
the identified depth of the reflective interface based on
previously obtained surface seismic data.
10. The method according to claim 9, wherein the identifying is
based on a difference in relative amplitude of reflections in the
seismic data in a given seismic section.
11. The method according to claim 9, wherein the identifying is
based on a difference in attribute values of reflections in the
seismic data in a given seismic section.
12. The method according to claim 8, further comprising disposing
at least two receptors in the second borehole, each of the at least
two receptors being equidistantly spaced from adjacent ones of the
at least two receptors.
13. The method according to claim 8, wherein the disposing the
seismic source includes the first depth in the first borehole being
less than a depth of the one or more receptors and a depth of the
target region in the second borehole.
14. A method of arranging a Vertical Seismic Profile (VSP) system,
the method comprising: identifying a reflective interface depth of
a reflective interface in an area of interest; positioning a
seismic source at a first depth, the first depth being below the
reflective interface depth in a first borehole within the area of
interest; and positioning two or more receptors in a second
borehole within the area of interest, the receptors being clamped
to the second borehole wall in selected positions to monitor a
target region for seismic profiling.
15. The method according to claim 14, wherein the selected
positions are at a depth that is greater than the first depth of
the seismic source in the first borehole.
16. The method according to claim 14, wherein the identifying the
reflective interface depth is based on interpreting previously
obtained surface seismic data in the area of interest.
17. The method according to claim 16, wherein the interpreting
includes observing a difference in amplitude values of reflections
in the surface seismic data in the area of interest.
18. The method according to claim 18, wherein the interpreting
includes observing a difference in attribute values of reflections
in the surface seismic data in the area of interest.
19. The method according to claim 14, wherein the positioning the
two or more receptors includes moving the two or more receptors
along the second borehole to record seismic signals in more than
one position.
20. The method according to claim 14, wherein the positioning the
seismic source includes moving the seismic source along the first
borehole to emit a seismic wave at more than one position.
21. The method according to claim 14, wherein the positioning the
seismic source includes rotating the seismic source to emit a
seismic wave in more than one direction.
Description
BACKGROUND
[0001] This invention is related to geophysical exploration and
more specifically to a borehole seismic method of exploration
[0002] In the mineral and petroleum exploration field, for decades
the utilization of geophysical methods has been imperative to map
the subsurface, improve the capability of finding hydrocarbons, and
reduce costs in exploration, drilling and production activities. In
this sense, Reflection Seismic is the most broadly used geophysical
method in petroleum exploration for mapping basin structures and
potential reservoirs, because the method has the ability to record
information from different layers disposed in the subsurface. Due
to the fact that acoustic signals related to different layers
arrive at different times, the reflection seismic technique is able
to produce stratified mapping (1D, 2D and 3D) of huge sedimentary
packages with significant detail. Besides the structural mapping,
the study of seismic attributes (amplitude, reflection coefficient,
frequency, impedance, velocity, etc.) is useful to better
understand the physical properties and characterize a reservoir in
large and middle scale.
[0003] The main reflection seismic methods applied in the oil
industry are the surface seismic and borehole seismic techniques
(Vertical Seismic Profiling). In surface seismic techniques, the
signal is generated at the surface or near the surface, and is
recorded by receivers also disposed at the earth surface or close
to the sea level. In turn, in Vertical Seismic Profiling (VSP) the
seismic source is usually located at or close to the surface and
the receptors are coupled to the wall of a drilled well.
[0004] The reflection seismic method is based on the propagation of
seismic waves or vibrations in the subsurface and a record of the
subsequently reflected signals when the waves reach interfaces that
separate layers with different physical properties. As the waves
propagate through the earth's interior, part of the energy is
reflected when the waves reach interfaces which separate layers
with different densities and elastic coefficients, and the other
part continues to propagate, reaching new interfaces and generating
new reflections until all the energy is dispersed. The seismic
signal is usually generated at the surface or near the surface, and
can be recorded by receivers also disposed at the earth surface or
close to the sea level (surface seismic) or by receivers placed in
the wells (VSP technique).
[0005] When the seismic wave propagates through the subsurface, the
seismic wave suffers several types of signal attenuation. These
include: (1) attenuation due to spherical divergence as the
traveled distance increases; (2) attenuation due to energy
reflection and refraction; (3) attenuation by diffraction due to
the rugous or irregular interfaces; and (4) high frequency
attenuation with the earth acting as a low-frequency bandpass
filter. In this sense, VSP, in comparison to conventional surface
seismic methods, allows recording of more intense signals with less
attenuation at higher based on the fact that the wave travel
distance between the source and the in-well receptors is shortened
(rather than requiring a round-trip to the surface). The better
quality data recorded in VSP normally presents more resolution and
allows the generation of more accurate seismic attribute data.
Moreover, due to the fact the receivers are placed in the
subsurface below the seismic sources, the method facilitates
recording of both down-going and up-going events (whereas the
surface seismic method can only record up-going events), and also
facilitates accurate estimation of intra-bed velocities in a short
interval and the direct correlation of the signal arrival time with
the event positioning in the subsurface (where receiver positions
in depth are known). However, when the target regions of interest
are in very deep zones, superposed by layers whose interfaces
present high acoustic impedance (e.g., salt and carbonate layers,
basalt sills, etc.), the prior VSP technique, too, is insufficient
because most of the seismic signal is attenuated/dispersed by
highly reflective interfaces in the subsurface (e.g., sea bottom,
salt top, salt base, carbonate platforms, basalt sills, etc.).
[0006] Thus, the mineral and hydrocarbons exploration industry
would appreciate a technique that provides greater resolution in
seismic imaging of targets located below thick sedimentary layers
superposed by highly reflective interfaces.
BRIEF SUMMARY
[0007] According to an embodiment, a system to obtain a Vertical
Seismic Profile (VSP) includes a seismic source disposed in a first
borehole at a first depth greater than an identified depth of a
interface, the seismic source configured to emit seismic waves; and
one or more receptors disposed in a second borehole that includes a
target region of interest, the one or more receptors configured to
receive direct and reflected components of the seismic waves.
[0008] According to another embodiment, a method of obtaining a
Vertical Seismic Profile (VSP) includes disposing a seismic source
in a first borehole at a first depth greater than an identified
depth of a reflective interface, the seismic source being
configured to emit seismic waves; and disposing one or more
receptors in a second borehole that includes a target region of
interest, the one or more receptors configured to receive direct
and reflected components of the seismic waves.
[0009] According to yet another embodiment, a method of arranging a
Vertical Seismic Profile (VSP) system includes identifying a
reflective interface depth of a reflective interface in an area of
interest; positioning a seismic source at a first depth, the first
depth being below the reflective interface depth in a first
borehole within the area of interest; and positioning two or more
receptors in a second borehole within the area of interest, the
receptors being clamped to the second borehole wall in selected
positions to monitor a target region for seismic profiling.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] The following descriptions should not be considered limiting
in any way. With reference to the accompanying drawings, like
elements are numbered alike:
[0011] FIG. 1 is a cross-sectional block diagram of an onshore
Vertical Seismic Profiling (VSP) system according to an
embodiment;
[0012] FIG. 2 is a cross-sectional block diagram of an offshore
Vertical Seismic Profiling (VSP) system according to an
embodiment;
[0013] FIG. 3 depicts a VSP system according to an embodiment
including a vertical first borehole;
[0014] FIG. 4 depicts a VSP system according to an embodiment
including a horizontal first borehole; and
[0015] FIG. 5 the processes involved in obtaining a seismic profile
of a target region based on an embodiment.
DETAILED DESCRIPTION
[0016] A detailed description of one or more embodiments of the
disclosed apparatus and method presented herein by way of
exemplification and not limitation with reference to the
Figures.
[0017] FIG. 1 is a cross-sectional view of an onshore Vertical
Seismic Profiling (VSP) system 100 according to an embodiment. The
exemplary VSP system 100 is shown to include one borehole seismic
source 110 emitting a seismic wave 120. However, in alternate
embodiments, two or more seismic sources 110 may be disposed in
proximity of each other. The seismic source 110 may be an
explosive, an air-gun, a sparkler, or some other known source of
seismic signals 120 able to be fired in a borehole 130. The seismic
source 110 is shown in a first borehole 130 penetrating the earth
140, which includes a target region 180 of interest. The seismic
source 110 is disposed below the highly reflective interface 150
shown in FIG. 1. Relatively regular reflective interfaces 155 are
also represented in the FIG. 1. The first borehole 130 may include
special casing to support repeated shots performed by the seismic
source 110 if necessary. The exemplary VSP system 100 is also shown
to include four receptors 160 (or receivers) in a second borehole
170, different than the first borehole 130 that includes the
seismic source 110. Either or both of the boreholes 130 and 170 may
be deviated or horizontal. In that case, the trajectory and angle
of the borehole (130, 170) must be measured and accounted for in
the subsequent processing of the received signals.
[0018] As shown, the receptors 160 are disposed at a depth that is
deeper than the depth at which the seismic source 110 is disposed.
This allows the receptors 160 to receive both down-going seismic
signal and the up-going primary reflected signals resulting from
the seismic wave 120 emitted by the seismic source 110. In
alternate embodiments, the receptors 160 may be positioned above
the seismic source 110 if required for a specific case study. The
receptors 160 are clamped to a preselected position of the borehole
170 wall (see exemplary clamping mechanism 161) to monitor the
target region 180. The clamping may improve the quality of the
recorded signals. The receptors 160 or array of receptors 160 are
clamped to the borehole 170 wall during use but may be decoupled to
be moved to another measuring position as needed. When receptors
160 are substantially equi-distant from each other, the received
signals can be regularly sampled. Each receptor 160 may include,
among other things, a single geophone, three-component geophones,
vertical geophones, hydrophones, orientation measuring system,
geophone-to-wall coupling measurement mechanism, downhole
digitizing system, and a connection to other receptors 160.
Additionally, each receptor 160 may include clamping mechanisms 161
as retractable locking arms, a telescoping ram, fixed bow spring,
hydraulic pistons, or any other apparatus that may be used to clamp
the receptor 160 to the borehole 170 wall. The seismic source 110
and the receptors 160 may be conveyed through the first borehole
130 and the second borehole 170, respectively, by carriers 190.
[0019] In various embodiments, the carrier 190 may be a drill
string (for Seismic While Drilling applications) or armored
wireline cable supported by a drill rig 195. The seismic source 110
and receptors 160 may be in communication, via telemetry, for
example, with one or more acquisition units 197. The seismic source
110 and the receptors 160 need not share the same one or more
acquisition units 197, which may include one or more memory
devices, user interfaces, acquisition systems, positioning systems,
source control systems, high precision clocks, etc. The acquisition
unit 197 may control the seismic source 110 and record and process
data from the receptors 160 using one or more processors 198.
Additionally, surface receptors 165 may control the seismic signal
120 produced by the seismic source 110 and correct the data
recorded downhole by the receptors 160 located in the borehole 170.
The signals recorded by the surface receptors 165 may also be used
to identify the influence that the layer above the seismic source
110 causes in the seismic signal 120 produced by this seismic
source 110. Although FIG. 1 illustrates two surface receptors 165,
only one or a number of surface receptors 165 may be used depending
on the survey objectives.
[0020] In alternate embodiments, the exemplary VSP system 100
described herein may be applied in Seismic While Drilling (SWD)
surveys. In this case, the receptors 160 and carrier 190 in the
borehole 170 will be utilized for SWD with the receptors 160 being
able to record data while drilling coupled a drilling column. As
noted above, the carrier 190 would be a drill string, for example.
High precision clocks may be included in the seismic source 110 and
in the receptors 160 to synchronize the shoot time and the
reception time, and precisely record signal travel times. The
exemplary VSP system 100 may be used onshore (FIG. 1), offshore (as
shown in FIG. 2) or in water bodies (lakes, lagoons, rivers, etc.),
in a variety of different depths and with different distances
between the boreholes 130 and 170.
[0021] FIG. 2 is a cross-sectional block diagram of an offshore
Vertical Seismic Profile (VSP) system 100 according to an
embodiment. When the VSP system 100 is used offshore or in other
places covered by water bodies, the receptors 165 need to be
appropriated to work under water and clamped on the sea bottom or
other water body bottom. Additionally in this case, one or more
hydrophones 166 may be placed from the drill rig 195 (or alike)
that supports the borehole seismic source 110 in the water and used
to record the seismic signals 120 produced by the source 110 that
cross the water column for better signal control and water column
velocity calculations. Still in the case of using the VSP system
100 offshore or in other places covered by water bodies, a surface
or near surface seismic source 199 may initially be used in the
water to perform a conventional VSP survey to identify highly
reflective interfaces 150 and regular reflective interfaces 155. In
this case, a hydrophone 166 may be disposed in the water below the
surface seismic source 199 for better monitoring the seismic signal
produced by the surface seismic source 199. Alternatively, the VSP
system 100 may be used to perform VSP surveys in a number of wells
at the same time. In such embodiments, the seismic source 110 would
be placed in a first borehole 130 surrounded by the other boreholes
(e.g., 170). Additionally, receptors 160 would be placed in the
boreholes (e.g., 170) that surround the first borehole 130. Each of
the other boreholes (e.g., 170) where the receptors 160 are placed
would include similar apparatus as in the borehole 170. Thus, when
seismic signals 120 are produced by the seismic source 110 placed
in the borehole 130, their resultant signals can be detected by the
receptors 160 placed in the other boreholes (e.g., 170) surrounding
the first borehole 130.
[0022] The one or more highly reflective interfaces 150 are
identified and approximated prior to positioning the seismic source
110 to ensure that the seismic source 110 is positioned below a
highly reflective interface 150 of interest. Typically, surface
seismic data may have already been obtained in an area where the
VSP survey is planned. Also, highly reflective interfaces 150 can
be identified through the interpretation of well log data, such as
acoustic logs, density logs, gamma ray logs, well velocity surveys
(checkshot surveys), or others useful logs previously performed in
the wells. The VSP system 100 itself may be used to identify the
highly reflective interfaces 150. In alternate embodiments, the
reflective interface 150 may be identified through interpretation
of data obtained previously from a conventional VSP survey using a
seismic source 199 at the surface or close to the surface. The data
obtained by the receptors 160, recording seismic signals produced
by the surface seismic source 199, is analyzed and interpreted to
identify the highly reflective interfaces 150. Specifically, highly
reflective interfaces 150 are identified as those areas where the
amplitude of reflections (of seismic waves) is relatively higher
than in other areas. Highly reflective interfaces are formed by
contact between two layers having significant differences in
physical properties (e.g., density, porosity, elastic coefficients,
seismic velocity). These interfaces generate strong reflections
that cannot necessarily be quantified for specific reflectivity or
amplitude values (because they are identified by relative strength
in a given area) but can be interpreted over the set of acquired
data. Different examples of seismic data can present a large
variation in the amplitude or reflectivity values. The seismic data
may be recorded in 8, 16, or 32 bits, and different processing
workflows or filters may be applied. For example, the minimum and
maximum amplitude values observed in a typical seismic section can
range between few hundreds (e.g. 8 bits data) or millions (e.g. 32
bits data). Thus, the interpretation of highly reflective
interfaces in seismic data is usually based on the identification
of reflections composed by relatively high amplitude (or
reflectivity) values, compared to the general context of the data.
Specific algorithms and software are used to interpret seismic
data. Besides amplitude and reflectivity, other seismic attributes
can be used to identify such highly reflective interfaces 150, as
well. As noted above, seismic attributes include reflection
coefficient, frequency, impedance, and velocity.
[0023] FIG. 3 depicts a VSP system 100 according to an embodiment
including a vertical first borehole 130. Although FIG. 3 shows one
seismic source 110, there may be two or more seismic sources 110
below the highly reflective interface 150. Also, in alternate
embodiments, the seismic source 110 or multiple seismic sources 110
may be moved along the borehole 130 and, additionally or
alternatively, the seismic source 110 may rotate in place to alter
the direction of the output seismic waves 120. The
multi-directional and multi-position seismic waves 120 enhance the
seismic coverage (or illumination) of the target region 180 and its
vicinity. FIG. 4 depicts a VSP system 100 according to an
embodiment including a horizontal first borehole 130. Although FIG.
4 shows four seismic sources 110, a single seismic source 110 may
be used, and the single seismic source 110 (or the displayed
multiple seismic sources 110) may be moved horizontally along the
borehole 130 or rotated. The array of seismic sources 110 shown in
FIG. 4 may be used to improve the signal redundancy and reduce the
survey time.
[0024] FIG. 5 depicts the processes 500 involved in obtaining a
seismic profile of a target region 180 based on an embodiment. At
block 510, the processes 500 include identifying one or more highly
reflective interfaces 150 in the area of interest (which includes
the target region 180). As discussed above, identifying a highly
reflective interface 150 includes interpreting seismic data and/or
well log data previously surveyed in the area. Seismic data can
also be obtained with a conventional VSP survey using the seismic
source 199 or the seismic source 110 to identify relatively higher
reflection amplitudes. In alternate embodiments, the reflective
interface 150 may be identified through interpretation of data
obtained previously from a conventional VSP survey using a seismic
source 199 at the surface or close to the surface. At block 520,
positioning the seismic source 110 below a highly reflective
interface 150 in a first borehole 130 includes using the previously
identified depth of at least one highly reflective interface 150.
As noted above, more than one seismic source 110 may be used to
reduce the survey time, increase the coverage of the area and the
redundancy of the detected signals. Also, the one or more seismic
sources 110 may be rotated in place and/or moved along the first
borehole 130. At block 530, positioning a receptor 160 near the
target region 180 in a second borehole 170 includes positioning the
receptor 160 below a depth of the seismic source 110 in the first
borehole 130. This ensures that both the down-going seismic signals
and up-going primary reflected signals based on seismic signals 120
emitted by the seismic source 110 are received at the receptor 160.
As noted above, more than one receptor 160 may be used. When more
than one receptor 160 is used, spacing the receptors 160
equi-distantly facilitates regular sampling of signals resulting
from the seismic wave 120. At block 440, controlling the seismic
source 110 is done by the acquisition unit 197. Block 540 also
includes the seismic source 110 emitting seismic signals 120 from
the first borehole 130, receiving incident and reflected seismic
signals at the receptors 160 in the second borehole 170, and
recording seismic signals and their respective travel times using
the acquisition unit 197. Receiving and recording resultant seismic
signals and their respective travel times at block 540 refers to
receiving and recording data at the receptors 160, surface
receptors 165, and hydrophones 166, as needed, to perform the
processing. At block 550, processing incident and reflected signals
resulting from seismic waves emitted by the seismic source 110 and
received by the one or more receptors 160 (and surface receptors
165, and hydrophones 166) provides VSP. As noted above, the
processing may be done by one or more processors 198 in an
acquisition unit 197 integrated with one or more memory
devices.
[0025] In support of the teachings herein, various analysis
components may be used, including a digital and/or an analog
system. For example, the acquisition unit 197 may include digital
and/or analog components. The VSP system 100 may have components
such as the acquisition unit 197, storage media, memory, input,
output, communications link (wired, wireless, pulsed mud, optical
or other), user interfaces, software programs, signal processors
(digital or analog) and other such components (such as resistors,
capacitors, inductors and others) to provide for operation and
analyses of the apparatus and methods disclosed herein in any of
several manners well-appreciated in the art. It is considered that
these teachings may be, but need not be, implemented in conjunction
with a set of computer executable instructions stored on a
non-transitory computer readable medium, including memory (ROMs,
RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any
other type that when executed causes a computer to implement the
method of the present invention. These instructions may provide for
equipment operation, control, data collection and analysis and
other functions deemed relevant by a system designer, owner, user
or other such personnel, in addition to the functions described in
this disclosure.
[0026] Further, various other components may be included and called
upon for providing for aspects of the teachings herein. For
example, a power supply, magnet, electromagnet, sensor, electrode,
transmitter, receiver, transceiver, antenna, controller, optical
unit, electrical unit or electromechanical unit may be included in
support of the various aspects discussed herein or in support of
other functions beyond this disclosure. The acquisition unit 197
may have or may not have communication link (wired, wireless,
optical or other) with one or more processors 198 to perform data
transferring, data processing and analysis.
[0027] Additionally, the data set acquired by the apparatus and
method described herein can be processed, reprocessed and/or
analyzed by one or more processors 198. The processor 198, in turn,
may include digital and/or analog components, one or multiple CPUs,
storage media, memory, input, output, communications link (wired,
wireless, optical or other), user interfaces, software programs,
signal processors (digital or analog) and other such components
(such as resistors, capacitors, inductors and others) to provide
processing and analyses of the data set acquired and recorded by
the apparatus and methods disclosed herein in any of several
manners well-appreciated in the art. It is considered that these
teachings may be, but need not be, implemented in conjunction with
a set of computer executable instructions stored on a
non-transitory computer readable medium, including memory (ROMs,
RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any
other type that when executed causes a computer to process and
analyze the data set provided by the present invention. These
instructions may provide for processor 198 equipment operations,
control, data collection, processing and analysis and other
functions deemed relevant by a system designer, owner, user or
other such personnel. The processor 198 may include a communication
link (wired, wireless, optical, satellite or other) with one or
more acquisition unit 197 to perform data transferring, data
processing, analysis and supporting others aspects of the
acquisition procedures of this disclosure. Alternatively, data
transferring between the acquisition unit 197 and the processor 198
can be provided by portable hard drives, memory cards, Compact
Disks, DVDs or other memory devices used by the industry. The
processor 198 may be integrated with or separate from the
acquisition unit 197.
[0028] Elements of the embodiments have been introduced with either
the articles "a" or "an." The articles are intended to mean that
there are one or more of the elements. The terms "including" and
"having" are intended to be inclusive such that there may be
additional elements other than the elements listed. The terms
"first," "second" and "third" are used to distinguish elements and
are not used to denote a particular order.
[0029] It will be recognized that the various components or
technologies may provide certain necessary or beneficial
functionality or features. Accordingly, these functions and
features as may be needed in support of the appended claims and
variations thereof, are recognized as being inherently included as
a part of the teachings herein and a part of the invention
disclosed.
[0030] While the invention has been described with reference to
exemplary embodiments, it will be understood that various changes
may be made and equivalents may be substituted for elements thereof
without departing from the scope of the invention. In addition,
many modifications will be appreciated to adapt a particular
instrument, situation or material to the teachings of the invention
without departing from the essential scope thereof. Therefore, it
is intended that the invention not be limited to the particular
embodiment disclosed as the best mode contemplated for carrying out
this invention, but that the invention will include all embodiments
falling within the scope of the appended claims.
* * * * *